It is common practice in completing oil and gas wells to set a string of pipe, known as casing, in the well and use cement around the outside of the casing to isolate the various formations penetrated by the well. To establish fluid communication between the hydrocarbon-bearing formations and the interior of the casing, the casing and cement sheath are perforated.
At various times during the life of the well, it may be desirable to increase the production rate of hydrocarbons by using appropriate treating fluids such as acids, solvents or surfactants. If only a short, single pay zone in the well has been perforated, the treating fluid will flow into the pay zone where it is required. As the length of the perforated pay zone or the number of perforated pay zones increases, the placement of the fluid treatment in the regions of the pay zones where it is required becomes more difficult. For instance, the strata having the highest permeability will most likely consume the major portion of a given stimulation treatment leaving the least permeable strata virtually untreated. Therefore, techniques have been developed to divert the treating fluid from its path of least resistance so that the low permeability zones are also treated.
One technique for achieving diversion involves the use of downhole equipment such as packers. Although these devices are effective, they are quite expensive due to the involvement of associated workover equipment required during the tubing-packer manipulations. Additionally, mechanical reliability tends to decrease as the depth of the well increases.
As a result, considerable effort has been devoted to the development of alternative diverting methods. One widely used diverting technique uses small rubber-coated balls, known as ball sealers, to seal off casing perforations.
These ball sealers are pumped into the wellbore along with the formation treating fluid. The balls are carried down the wellbore and onto the perforations by the flow of the fluid through the perforations into the formation. The balls seat upon the perforations and are held there by the pressure differential across the perforations.
Major advantages of utilizing ball sealers as a diverting agent include ease of use, positive shutoff, no involvement with the formation, and low risk of incurring damage to the well. The ball sealers are injected at the surface and transported by the treating fluid. Other than a ball injector, no special or additional treating equipment is required. The ball sealers are designed to have an outer covering sufficiently compliant to seal a jet formed perforation and to have a solid, rigid core which resists extrusion into or through the perforation. Therefore, the ball sealers will not penetrate the formation and permanently damage the flow characteristics of the well.
Several requirements are repeatedly applied to ball sealers as they are normally utilized today. First the ball sealers must be chemically inert in the environment to which they are exposed. Second, they must seal effectively, yet not extrude into the perforations. Third, the ball sealers must release from the perforations when the pressure differential into the formation is relieved.
To meet these requirements, various materials for ball sealers have been suggested including rubber, nylon, plastic, aluminum, rubber-coated aluminum, rubber-covered phenolic, rubber-covered nylon, and even permeable plastic consolidated walnut hull balls. One difficulty with ball sealers composed of such materials is that the balls which are currently available often do not exhibit sufficient resistance to chemical attack by treating fluids. Another difficulty is that materials having a temperature resistance suitable for high temperature applications have a high density as compared to common treating fluids. In the case of rubber coated balls, the perforation can actually cut the rubber covering in the area of the pressure seal. Once the ball sealer loses its structural integrity the unattached rubber is free to lodge permanently in the perforation which can reduce the flow capacity of the perforation and may permanently damage the well. Excessive heat, such as is present in deep wells can also cause such ball sealers to lose structural integrity. Deeper drilling has demanded stimulation jobs that are conducted under conditions that exceed the current temperature and pressure limitations of available low density ball sealers. Available low density ball sealers are not suitable for temperatures over 350.degree. F. (177.degree. C.) or pressures over 8,000 psi (562.5 kg/cm.sup.2).
A need exists for improved low density ball sealers which function well in such hot, hostile environments, especially in the presence of acidic fluids.